Drill-In Fluids For Oil and Gas Reservoirs With High Carbonate Contents

ABSTRACT

Compositions Including Relatively Low Reactivity Acids, Mixed with viscoelastic surfactants (VESs) and internal breakers may serve as drill-in fluids to open underground hydrocarbon reservoirs with carbonate contents of 10 wt % or above. The drill-in fluids have low viscosities in the drilling pipe. After the fluid flows out of the drill bit, the acids react with carbonates in the formation thereby increasing the pH of the drill-in fluids causing the VES to gel the fluid at the bottom of the hole and the downhole annulus between the drilling pipe and the formation rock. The viscosified drill-in fluid will reduce fluid loss and will carry no dissolved drilling debris to the surface. After drilling through the targeted formation, the internal breakers in the viscosified drill-in fluids will break down the fluids to permit their removal, and the well is ready to produce with very little or no near well bore damage.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part patent application from U.S.patent application Ser. No. 11/626,163 filed Jan. 23, 2007.

TECHNICAL FIELD

The present invention relates to methods of drilling through reservoirsections of subterranean formations during hydrocarbon recoveryoperations, and more particularly relates, in one non-limitingembodiment, to using drill-in fluids that contain viscoelasticsurfactants and relatively low reactivity acids to drill throughsubterranean reservoirs having relatively high carbonate contents whichreact with the acids.

TECHNICAL BACKGROUND

Drill-in fluids are special fluids designed exclusively for drillingthrough the reservoir section of a subterranean formation. The reasonsfor using a specially designed drilling muds include, but are notnecessarily limited to (1) to drill the reservoir zone successfully,which is often a long, horizontal drain hole, (2) to minimize damage ofthe near-wellbore region and maximize the production of exposed zones,and (3) to facilitate the necessary well completion. Well completion mayinclude complicated procedures. Typically, drill-in fluids may resemblecompletion fluids. Drill-in fluids may be brines containing onlyselected solids of appropriate particle size ranges (for instance, saltcrystals or calcium carbonate) and polymers. Usually, only additivesneeded for filtration control and cuttings carrying are present in adrill-in fluid.

As noted, drill-in fluids may contain filtration control additives toinhibit or prevent loss of the drill-in fluid into the permeableformation. Fluid loss involves the undesired leakage of the liquid phaseof drill-in fluid containing solid particles into the formation matrix.The resulting buildup of solid material or filter cake against theborehole wall may be undesirable, as may be the penetration of thefilter cake into the formation. The removal of filter cake, whichsometimes must be done by force, may often result in irreparablephysical damage to the near-wellbore region of the reservoir. Fluid-lossadditives are used to control the process and avoid potential damage ofthe reservoir, particularly in the near-wellbore region.

It would thus be desirable to discover drill-in fluid which would haverelatively low viscosity in the drilling pipe but which would shortlyafter leaving the drill bit increase in viscosity and inhibit or preventfluid leak-off into the formation, while minimizing formation damage.

SUMMARY

There is provided in one non-restrictive version, a method of drillinginto a subterranean formation which includes preparing a drill-in fluidthat contains water, at least one viscoelastic surfactant (VES) and atleast one acid. The acid may be an organic acid and/or a mineral acid,and in one non-limiting embodiment is a relatively low reactivity acid.The VES is present in the drill-in fluid in an amount that is effectiveto increase the viscosity of the drill-in fluid except for the presenceof the at least one acid. That is, because the acid is present, gellingof the fluid by the VES is initially prevented. The drill-in fluid isused to drill a wellbore into a subterranean formation. Once the fluidexits the drill bit, the acid in the drill-in fluid is at leastpartially consumed by reaction of the acid with a mineral in thesubterranean formation, in one non-limiting embodiment a carbonate, e.g.calcium carbonate, or an evaporite, a salt dome, shale, and combinationsthereof. The consumption of the acid from the fluid increases the pH ofthe drill-in fluid to an extent sufficient that the VES increases theviscosity of the drill-in fluid in at least a portion of an annulusadjacent the wellbore which in turn inhibits fluid loss into theformation.

There is also provided, in another non-limiting form, a drill-in fluidthat contains water, at least one viscoelastic surfactant (VES) and atleast one acid which may be an organic acid, a mineral acid andcombinations thereof. The VES is present in an amount effective toincrease the viscosity of the drill-in fluid except for the presence ofthe acid. The drill-in fluid may optionally contain at least oneinternal breaker which may “break” or reduce the viscosity of the gelledfluid adjacent the wellbore once drilling the reservoir section iscomplete. The increase in viscosity of the drill-in fluid may beaccomplished by the VES forming elongated micelles which becomephysically entangled with one another, such as schematically illustratedin FIG. 2. Viscosity enhancers may be optionally present to associate orgroup or “connect” the elongated micelles together to increase theability of the gelled drill-in fluid to inhibit or prevent leak-off ofthe fluid into the reservoir or formation. Another optional component ofthe drill-in fluid is mineral oil, which may be present in an amounteffective to further reduce fluid loss into the reservoir or formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a photograph that shows how an aqueous fluid containing spentdicarboxylic acid (HTO™ acid), a relatively low reactivity acid,containing a VES gelling agent exhibits very high viscosity at staticand very low fluid shear rate conditions;

FIG. 2 is a schematic illustration of physical entanglement of elongatedrod-like VES micelles composed of VES molecules which are thought toincrease viscosity of a gelled fluid;

FIG. 3 is a schematic illustration of how internal breaker molecules,such as polyenoic acids, may associate with VES micelles, and how uponauto-oxidation of the polyenoic acids into by-products will alter theelongated or rod-like micelle structures causing the viscosity to reduceor “break” by changing the elongated micelles into non-viscous sphericalshape micelle structures;

FIG. 4 is a graph showing that the viscosity of aqueous fluidscontaining a VES gelling agent and 10% of a dicarboxylic acid (HTO™acid), either with or without an internal breaker, increases withincreasing pH as the acid reacts with carbonate;

FIG. 5 is a graph of showing the viscosities of fluids gelled with a VESafter the dicarboxylic acid (HTO™ acid) is spent without and with aninternal breaker included at 140° F. (60° C.), as a function of shearrate;

FIG. 6 is a graph of viscosity of a fluid initially gelled with a VEShaving spent dicarboxylic acid (HTO™ acid) at 160° F. (71° C.) and a 100l/s shear rate containing a fish oil internal breaker that is high inpolyunsaturated fatty acids demonstrating effective viscosity reduction;

DETAILED DESCRIPTION

An aqueous system comprising a relatively low reactivity acid, aviscoelastic surfactant and an internal breaker has been discovered tobe a useful drill-in fluid to penetrate subterranean formations via awell bore. These drill-in fluids may open underground oil and/or gasreservoirs having carbonate contents of 10 wt % or more. The drill-influids have low viscosities within the drilling pipe since the amount ofacid is sufficient to keep the VES from gelling or increasing theviscosity of the water. During drilling, the fluid flows out at thedrill bit and the acid reacts with the carbonate and other minerals inthe formation. This increases the pH of the drill-in fluid and the VESwill gel the fluid at the bottom of the hole and the downhole annulusbetween the drilling pipe and the formation rock, that is, adjacent thewellbore. This gelled fluid inhibits the fluid loss of the drill-influid into the formation. The viscosified drill-in fluid also will carrynon-dissolved and/or non-dissolvable drilling debris, e.g. cuttings tothe surface while it is gelled. The gelled fluid is not too viscous asto inhibit the motion or rotation of the drill string. Further, sincelow reactivity acids are employed, potential corrosion of the drillstring, drill bit and other equipment is minimized. After the viscousVES fluid is circulated to surface, fresh acid will need to be added tothe drill-in VES fluid for continue drilling.

After drilling through the targeted reservoir or formation, the internalbreakers in the viscosified drill-in fluid will subsequently break downthe entangled and elongated micelles and the drill-in fluid may beproduced back. The well is then ready to be produced having no or verylittle near-wellbore damage. Compared with a drill-in fluid containingno acid, this drill-in fluid system will increase drilling speed by anadditional chemical means as the acid reacts with the contactedformation rock. Optionally, high viscosity mineral oil may be added tothe drill-in fluid system to further improve fluid loss control.

As noted, a viscous gel starts to develop when the acid contacts andreacts with the carbonate in the subterranean formation. As the acid isspent, the pH of the fluid at that location increases and in turn theviscosity of the acid VES fluid increases. This phenomenon isillustrated in FIG. 1. The viscoelastic surfactant gelled acid fluid(that contains fish oil or other internal breaker) maintains a higherviscosity to inhibit or prevent the fluid from leaking off into theformation. After completion of drilling through the target formation,the monoenoic or polyenoic acid (e.g. fish oil) or other substance actsas an internal breaker to break the viscous gel, i.e. to lower theviscosity of the fluid. The internally broken acid-spent VES fluid isthen very easy to flow back with the producing fluid, leaving little orno damage to the formation. Very little reservoir pressure or time isrequired to produce and clean up the broken acid-spent VES fluid.

The drill-in fluid contains relatively low reactivity acids. It has beenfound that particularly useful low reactivity acids are organic acidsthat contain at least one water-soluble dicarboxylic acid. In onenon-limiting embodiment herein, the dicarboxylic acid is of relativelylow molecular weight, that is, has a formula weight of 175 or less.Suitable dicarboxylic acids therefore include, but are not necessarilylimited to, oxalic acid (ethanedioic acid), malonic acid (propanedioicacid), succinic acid (butanedioic acid), glutaric acid (pentanedioicacid), adipic acid (hexanedioic acid), pimelic acid (heptanedioic acid),and mixtures thereof. In another non-restrictive version, thedicarboxylic acids are selected from the group consisting of succinicacid, glutaric acid, adipic acid, and mixtures thereof. Interestingly,glutaric acid, succinic acid, and adipic acid have been used ascomponents for corrosion inhibitors for ferrous metals, according toU.S. Pat. No. 4,512,552. Mixtures of succinic acid, glutaric acid, andadipic acid are generally available as a by-product stream. Moreinformation may be found in U.S. Pat. No. 6,805,198 to Huang, et al.assigned to Baker Hughes Incorporated, and incorporated herein byreference in its entirety.

Other suitable relatively low reactivity acids include, but are notnecessarily limited to, acetic acid, malic acid, lactic acid, polylacticacid, glycolic acid, polyglycolic acid, formic acid, citric acid,tartaric acid, methanesulfonic acid, low concentration hydrochloricacid, and combinations thereof. Low concentration HCl is defined hereinas equal to or less than 7.5%, alternatively equal to or less than 5%.High concentration HCl is defined herein as greater than 7.5%,alternatively greater than 10%. The acids may be liquids or solids aslong as they react with and are consumed by the minerals in thereservoir being drilled.

The minerals suitable to react with the acids of the drill-in fluidinclude, but are not necessarily limited to, carbonates, evaporites,salt domes, shales, and combinations thereof. Evaporites are a class ofsedimentary minerals and sedimentary rocks that form by precipitationvia evaporating an aqueous fluid. Common evaporite minerals includecalcite, aragonite, dolomite, halite, gypsum and anhydrite, which canform as seawater evaporates, and the rocks limestone and dolostone.Certain evaporite minerals, particularly halite, may form excellent caprocks or seals for hydrocarbon traps because they have minimal porosityand they tend to deform plastically (as opposed to brittle fracturingthat would facilitate leakage). The minerals reacted with the lowreactivity acids herein include stringers, which are shale layers. Shaleis a fine-grained, fissile, detrital sedimentary rock formed byconsolidation of clay- and silt-sized particles into thin, relativelyimpermeable layers. Shale is the most abundant sedimentary rock. Shalecan include relatively large amounts of organic material compared withother rock types and thus it has the potential to become a richhydrocarbon source rock, even though a typical shale contains just 1%organic matter. Its typical fine grain size and lack of permeability, aconsequence of the alignment of its platy or flaky grains, allow shaleto form a good cap rock for hydrocarbon traps.

The amount of acid in the drill-in fluid ranges from about 0.5 to about30 wt %, alternatively from about 1.0 to about 20 wt %.

Suitable solvents or diluents for the acid compositions herein include,but are not necessarily limited to, water, methanol, isopropyl alcohol,alcohol ethers, aromatic solvents, glycols, and mixtures thereof. In onenon-limiting embodiment, the composition has an absence ofmonocarboxylic acids and/or an absence of tricarboxylic acids.Alternatively, in another embodiment, the acid composition has anabsence of quaternary ammonium compounds and/or an absence ofsulfur-containing corrosion inhibitor activator (e.g. thioglycolic acid,alkali metal sulfonate, etc.). In one non-limiting embodiment, a goalherein is to avoid the use of strong mineral acids, such as highconcentrations of HCl and/or H₂SO₄, so these acids should be absent fromthe acid composition in one preferred, alternate embodiment. Again, highconcentration is defined herein as greater than 7.5%, alternativelygreater than 10%. The acid compositions herein are intended to replacethe mineral acid systems previously used, in one non-limiting aspect.

In one non-limiting embodiment, the drill-in fluid herein can optionallycontain at least one water soluble salt. Selected types and amounts ofwater soluble salts may be used to optimize the viscosity and elasticityof the aqueous drill-in as the low-reactivity acid spends on evaporiteminerals at reservoir temperature. The addition of water soluble saltsmay further be useful to increase the aqueous fluid weight (i.e.density) for developing hydrostatic pressure to control reservoir fluidpressure during drilling. The water soluble salts may include, but arenot necessarily limited to: NaCl, KCl, NH₄Cl, CaCl₂, MgCl₂, NaBr, CaBr₂,sodium formate, potassium formate, sodium salicylate, and combinationsthereof.

As noted, aqueous fluids gelled with viscoelastic surfactants aretypically used in wellbore completions, such as hydraulic fracturing,without the use of an internal breaker system, since conventionally andtypically they rely on external downhole conditions for the VES-gelledfluid to break, such as dilution with reservoir brine and moreimportantly gel breaking through interaction with reservoir hydrocarbonsduring production of such reservoir fluids to the surface. However,reliance on external downhole conditions has shown instances whereunbroken or poorly broken VES fluid remains within the reservoir after aVES fluid treatment and has impaired hydrocarbon production. There areaqueous fluids gelled with viscoelastic surfactants that are known to be“broken” or have their viscosities reduced, although some of the knownbreaking methods utilize external clean-up fluids as part of thetreatment design (such as pre- and post-flush fluids placed within thereservoir before and after well completion treatments, such asconventional gravel packing and also “frac-packing”—hydraulic fracturingfollowed by gravel packing treatment). There are other known methods,but they are relatively slow—for instance the use of VES-gel breakingbacteria with fluid viscosity break times ranging from half a day up to7 days.

There has evolved in the art an industry standard need for “quick gelbreak”, but for VES-gelled fluids this has been a substantiallychallenging problem. There needs to be a method for breaking VES-gelledfluids that can be as easy, as quick, and as economic as breakingconventional crosslinked polymer fluids, preferably using an internalbreaker. At the same time, it is not desirable to reduce the viscosityof the fluid, i.e. break the gel immediately or essentiallyinstantaneously. The VES-gelled aqueous fluid should maintain itsviscosity for a sufficient period of time to perform its intendedpurpose, for instance, inhibiting or preventing fluid leakoff into thereservoir during the drill-in operation. Of concern is the fact than anunbroken VES fluid has exceptionally high viscosity at very low shearrate and static conditions which makes it difficult for reservoirhydrocarbons to contact all of the VES fluid and to displace it from thepores of a treated reservoir. This is particularly true for gasreservoirs and crude oil reservoirs that have heterogeneous permeabilitywith high relative permeability sections present.

A new method has been discovered to reduce the viscosity of aqueousfluids gelled with viscoelastic surfactants (i.e. surfactants thatdevelop viscosity in aqueous brines, including chloride brines, byformation of rod- or worm-shaped micelle structures). The method removesthe need or reliance on reservoir hydrocarbons to contact, break, andclean up the viscoelastic fluid. The improvement will allow relativelyvery quick breaks, such as within 1 to about 16 hours, compared to thecurrent technology of using bacteria to break VES which takes at least48 or more hours, and more typically 4 to 7 days. In anothernon-limiting embodiment the break occurs within 1 to about 8 hours;alternatively from 1 to about 4 hours, and in another non-restrictiveversion 1 to about 2 hours. The breaker component herein may be used asan internal breaker, e.g. added to the gel after batch mixing of aVES-gel treatment, or added on-the-fly after continuous mixing of aVES-gel treatment using a liquid additive metering system in onenon-limiting embodiment, or the components can be used separately, ifneeded, as an external breaker solution to remove VES gelled fluidsalready placed downhole. The acids, e.g. dicarboxylic acids, in thesystem herein generally keep the VES from gelling the aqueous fluiduntil the fluid reaches a carbonate or other mineral-containingformation that reacts with the acids and raises the local pH of thatpart of the fluid. When this happens, which is after the fluid exits thedrill bit, the fluid gels and acts as a temporary barrier within theannulus adjacent the wellbore wall to inhibit or prevent the fluid fromleaking into the reservoir. Generally, the pH of the fluid being 4 orlower is sufficient to inhibit gelling. Once the pH increases to about4.2, or alternatively to about 4.5, VES gelling of the fluid will occur.

The internal breakers (e.g. hydrogenated polyalphaolefin oils, saturatedfatty acids, polyunsaturated fatty acids, and the like) are notsolubilized in the brine, since they are inherently hydrophobic, butrather interact with the VES surfactant elongated or worm-like micellestructures initially as dispersed microscopic oil droplets and thus forman oil-in-water type emulsion where the oil droplets are dispersed inthe internal phase as a discontinuous phase of the brine medium/VESfluid which is the outer phase or continuous phase. Additionally, it ispossible for the internal breaker (e.g. unsaturated fatty acids) toexist as individual compounds or molecules 14 associating with thehydrophobic tail portion of the VES molecules 12, and thereby bedispersed within the elongated or rod-like VES micelles 10, asschematically illustrated in FIG. 3. Laboratory tests have showed thatsmall amounts of unsaturated fatty acids, enough to eventuallycompletely the break VES viscosity, will not spontaneously degrade VESviscosity upon individual association and dispersion within the VESmicelles, but will become active to degrade VES viscosity upon anactivation event, such as auto-oxidation of the fatty acids toby-products that disrupt the elongated, “rod-like” or “worm-like”micelles. In one non-limiting embodiment, the structure of theVES-molecules becomes spherical or “ball-like” as seen at 20 in FIG. 3,which spheres 20 do not associate with or entangle each other toincrease the viscosity of the fluid in which they reside as do theelongated “rod-like” or “worm-like” micelles.

In one non-limiting embodiment, the viscosity of the VES-gelled aqueousfluid is not immediately reduced or broken. Reducing the viscosity ofthe gel or “breaking” of the fluid should not occur essentiallyinstantaneously. By “essentially instantaneously” is meant less thanone-half hour. The rate of viscosity break for a given reservoirtemperature by the methods described herein is controlled by type andamount of salts within the mix water (i.e. seawater, KCl, NaBr, CaCl₂,CaBr₂, NH₄Cl and the like), presence of a co-surfactant (i.e. sodiumdodecyl sulfate, sodium dodecyl benzene sulfonate, potassium laurate,potassium oleate, sodium lauryl phosphate, and the like), VES type (i.e.amine oxide, quaternary ammonium salt, and the like), VES loading, theamount of breaker used, the presence of components such as aromatichydrocarbons, and the like.

It is not important to add the internal breaker after the VES is addedto the aqueous fluid. That is, order of addition for the internalbreaker, e.g., plant oil, fish oil, and the like is not important.Additionally, in the acid-containing fluids herein, substantial gellingis not expected due to the presence of the dicarboxylic or otheracid(s). The acids have been found, in unspent form, to not allow theVES gelling agent to yield viscosity, i.e. to prevent viscositydevelopment. By “substantially gelled” herein is meant that at least 30%of the total viscosity increase has been achieved. In most cases, due tolow fluid pH, less than 2% of the total VES viscosity will occur.However, it has been found that the presence of an internal breaker,including but not limited to monoenoic and polyenoic acids, will notprevent the VES gelling agent from viscosifying the acid treatment fluidupon acid spending and fluid pH increasing. A novel and unique featureherein is how the internal breakers may be present during generation ofVES viscosity but yet still act as VES viscosity breakers over time atreservoir temperature.

In one non-limiting embodiment these gel-breaking products work byrearrangement of the VES micelles from rod-shaped or worm-shapedelongated structures to spherical structures, as schematicallyillustrated in FIG. 3. The breaking components described herein may alsoinclude the unsaturated fatty acid or polyenoic and monoenoic componentsof U.S. Patent Application Publication 2006/0211776, as well as theparent application hereto U.S. Ser. No. 11/626,163, both of which areincorporated herein by reference in their entirety. In one non-limitingembodiment these unsaturated fatty acids (e.g. oleic, linoleic,linolenic, eicosapentaenoic, etc.) may possibly be used alone, in oilsthey are commonly found in (flax oil, soybean oil, etc), and can beprovided as custom fatty acid blends (such as Fish Oil 18:12 TG byBioriginal Food & Science Corp.), or used together with other suitableinternal breakers. In some cases it is preferred that the plant or fishoil be high in polyunsaturated fatty acids, such as the use of flax oil,salmon oil, and the like. The plant and fish oils may be refined,blended and the like to have the desired polyunsaturated fatty acidcomposition modified for the compositions and methods herein.

In one non-limiting embodiment, the breaking or viscosity reduction isactivated, triggered or initiated by heat. These plant, and animal oilswill relatively slowly, upon heating, break or reduce the viscosity ofthe VES gel with the addition of or in the absence of any otherviscosity reducing agent. The amount of internal breaker (fish oil,e.g.), needed to break a VES-gelled fluid appears temperature dependent,with less needed as the fluid temperature increases. For unsaturatedfatty acid oils the type and amount of unsaturation (i.e. double carbonbonds) appears to be the major influence on the rate at which the fattyacid oil will break the VES-gelled fluid at a given temperature. Once afluid is completely broken at an elevated temperature and cooled to roomtemperature a degree of viscosity reheal may occur but in most cases norehealing is expected. Strangely enough all of the listed oils willallow initial VES to gel but then later act as controllable breakerswith little to no fluid reheal upon breaking. The effective amount ofplant oil and/or fish oil ranges from about 0.1 to about 15 gptg basedon the total fluid, in another non-limiting embodiment from a lowerlimit of about 0.5. Independently the upper limit of the range may beabout 10 gptg based on the total fluid. (It will be appreciated thatunits of gallon per thousand gallons (gptg) are readily converted to SIunits of the same value as, e.g. liters per thousand liters, m³/1000 m³,etc.)

Controlled viscosity reduction rates can be achieved at a temperature offrom about 70° F. to about 400° F. (about 21 to about 204° C.), andalternatively at a temperature of from about 100° F. independently to anupper end of the range of about 280° F. (about 38 to about 138° C.), andin another non-limiting embodiment independently up to about 300° F.(149° C.), where “independently” means any combination of the listedlower and upper thresholds. In one non-limiting embodiment, the fluiddesigner would craft the fluid system in such a way that the VES gelwould break at or near the formation temperature after drillin wasaccomplished.

In one non-limiting embodiment, fluid internal breaker design would bebased primarily on formation temperature, i.e. the temperature the fluidwill be heated to naturally in the formation once the drilling is over.Fluid design may take into account the expected cool down of the fluidduring a drilling.

The use of the disclosed breaker system is ideal for controllingviscosity reduction of VES based fluids. The breaking system may also beused for breaking gravel pack fluids, fracturing fluids, acidizing ornear-wellbore cleanup diverter fluids, and loss circulation pill fluidscomposed of VES. The breaker system may additionally work for foamedfluid applications (hydraulic fracturing, acidizing, and the like),where N₂ or CO₂ gas is used for the gas phase. This VES breaking methodis a significant improvement in that it gives breaking rates for VESbased fluids that the industry is accustomed to with conventionalpolymer based fracturing fluids, such as borate crosslinked guar.Potentially more importantly, the use of this internal breaker system incombination with external downhole breaking conditions should helpassure and improve hydrocarbon production compared to prior methods thatuses only external mechanisms to break the VES fluid for effective andcomplete VES fluid cleanup after a treatment.

In one non-limiting embodiment, the compositions herein will degrade thegel created by a VES in an aqueous fluid, by disaggregation orrearrangement of the VES micellar structure. However, the inventors donecessarily not want to be limited to any particular mechanism.

It is sometimes difficult to specify with accuracy in advance the amountof the various breaking components that should be added to a particularaqueous fluid gelled with viscoelastic surfactants to sufficiently orfully break the gel, in general. For instance, a number of factorsaffect this proportion, including but not necessarily limited to, theparticular VES used to gel the fluid; the particular plant, and/or fishoil used; the temperature of the fluid; the downhole pressure of thefluid, the starting pH of the fluid; the type and amount of salts; andthe complex interaction of these various factors. Nevertheless, in orderto give an approximate feel for the proportions of the various breakingcomponents to be used in the method herein, approximate ranges will beprovided. In an alternative, non-limiting embodiment the amount of fishor plant oil that may be effective in the method may range from about 5to about 25,000 ppm, based on the total amount of the fluid. In anothernon-restrictive version, the amount of fish or plant oil may range froma lower end of about 50 independently to an upper end of about 12,000ppm.

Any suitable mixing apparatus may be used for this procedure. In thecase of batch mixing, the acid, the VES gelling agent, the internalbreaker and the aqueous fluid are blended for a period of time. Thevegetable, and/or animal oil may be added during batch mixing or on thefly during the drilling. The preferred method is batch mixing alladditives together prior to being pumped downhole. The VES typicallywill be added to the aqueous fluid after the dicarboxylic acid addition,but may be added on the fly during the treatment. Some initial gellingof the VES prior to the acid encountering carbonate in the formation maybe acceptable, although in most cases this should not occur due to theinitial pH of the fluid being too low, typically less than 4.0 pH.

The VES that is useful herein can be any of the VES systems that arefamiliar to those in the well service industry, and may include, but arenot limited to, amines, amine salts, quaternary ammonium salts,amidoamine oxides, amine oxides, mixtures thereof and the like. Suitableamines, amine salts, quaternary ammonium salts, amidoamine oxides, andother surfactants are described in U.S. Pat. Nos. 5,964,295; 5,979,555;and 6,239,183, incorporated herein by reference in their entirety.

Viscoelastic surfactants improve the drilling fluid performance throughthe use of a polymer-free system. These systems, compared to polymericbased fluids, can offer improved viscosity breaking, higher sandtransport capability (where appropriate), are in many cases more easilyrecovered after drilling than polymers, and are relatively non-damagingto the reservoir with appropriate contact with sufficient quantity ofreservoir hydrocarbons, such as crude oil and condensate. The systemsare also more easily mixed “on the fly” in field operations and do notrequire numerous co-additives in the fluid system, as do some priorsystems.

The viscoelastic surfactants suitable for use herein include, but arenot necessarily limited to, non-ionic, cationic, amphoteric, andzwitterionic surfactants. Specific examples of zwitterionic/amphotericsurfactants include, but are not necessarily limited to, dihydroxylalkyl glycinate, alkyl ampho acetate or propionate, alkyl betaine, alkylamidopropyl betaine and alkylimino mono- or di-propionates derived fromcertain waxes, fats and oils. Quaternary amine surfactants are typicallycationic, and the betaines are typically zwitterionic. The thickeningagent may be used in conjunction with an inorganic water-soluble salt ororganic additive such as phthalic acid, salicylic acid or their salts.

Some non-ionic fluids are inherently less damaging to the producingformations than cationic fluid types, and are more efficacious per poundthan anionic gelling agents. Amine oxide viscoelastic surfactants havethe potential to offer more gelling power per pound, making it lessexpensive than other fluids of this type.

The amine oxide gelling agents RN⁺(R′)₂O⁻ may have the followingstructure (I):

where R is an alkyl or alkylamido group averaging from about 8 to 24carbon atoms and R′ are independently alkyl groups averaging from about1 to 6 carbon atoms. In one non-limiting embodiment, R is an alkyl oralkylamido group averaging from about 8 to 16 carbon atoms and R′ areindependently alkyl groups averaging from about 2 to 3 carbon atoms. Inan alternate, non-restrictive embodiment, the amidoamine oxide gellingagent is Akzo Nobel's AROMOX® APA-T formulation, which should beunderstood as a dipropylamine oxide since both R′ groups are propyl.

Materials sold under U.S. Pat. No. 5,964,295 include CLEARFRAC™, whichmay also comprise greater than 10% of a glycol. One preferred VES is anamine oxide. As noted, a particularly preferred amine oxide is APA-T,sold by Baker Oil Tools as SURFRAQ™ VES. SURFRAQ is a VES liquid productthat is 50% APA-T and greater than 40% propylene glycol. Theseviscoelastic surfactants are capable of gelling aqueous solutions toform a gelled base fluid. The additives are used to prepare a VES systemsold by Baker Oil Tools as DIAMONDFRAQ™. DIAMONDFRAQ™ with its assuredbreaking technology overcomes reliance on external reservoir conditionsin order to break, as compared with products such as CLEARFRAC™.

The methods and compositions herein also cover commonly known materialsas AROMOX® APA-T manufactured by Akzo Nobel and other known viscoelasticsurfactant gelling agents common to stimulation treatment ofsubterranean formations.

The amount of VES included in the drill-in fluid depends on at least twofactors after fluid pH increased. One involves generating enoughviscosity to control the rate of fluid leak off into the pores of thereservoir, and the second involves creating a viscosity high enough tocarry drilling debris to surface, in the non-limiting case of a drill-influid. Thus, depending on the application, the VES is added to theaqueous fluid in concentrations ranging from about 0.5 to 25% by volume,alternatively up to about 12 vol % of the total aqueous fluid (fromabout 5 to 120 gptg). In another non-limiting embodiment, the range forthe present formulations is from about 1.0 to about 6.0% by volume VESproduct. In an alternate, non-restrictive form, the amount of VES rangesfrom a lower limit of about 2 independently to an upper limit of about10 volume %.

A value of the compositions and methods herein is that a drill-in fluidmay be designed to have enhanced breaking characteristics. That is,fluid breaking is no longer solely dependent on external reservoirconditions for viscosity break and is controllable: the rate ofviscosity reduction, if complete break is achieved/occurs throughout thereservoir interval. Importantly, better clean-up of the VES fluid fromthe formation and wellbore can be achieved thereby. Better clean-up ofthe VES directly influences the success of the drill-in operation, whichis an enhancement of the well's hydrocarbon productivity. VES fluidclean-up limitations and failures of the past can now be overcome orimproved by the use of fluid compositions disclosed herein.

It has been further discovered that the addition of certain highviscosity mineral oils in relatively small quantities to an aqueousfluid gelled with a VES improved the fluid loss of these brines, but notin proportions high enough to interfere with the breaking of theVES-gelled fluid. The types and proportions of mineral oils describedherein do not noticeably change the initial viscosity of VES-gelledfluids for at least 90 minutes, which is surprising given that reservoirhydrocarbons are known to break VES-gelled fluids.

This discovery allows the VES system to have improved fluid loss to helpminimize formation damage during the drill-in operation. That is, theintroduction of these additives to the VES-gelled aqueous system willlimit and reduce the amount of VES fluid which leaks-off into the poresof a reservoir during a drill-in procedure, thus minimizing theformation damage that may occur by the VES fluid within the reservoirpores. Also, limiting the amount of VES fluid that leaks-off into thereservoir during a treatment will allow more fluid to remain within theannulus and thus less total fluid volume will be required for thedrill-in procedure.

In one non-limiting embodiment the mineral oil is added before the VESgelling agent. In another non-limiting embodiment herein the mineral oilis added after the aqueous fluid is substantially gelled. By“substantially gelled” is meant that at least 90% of the viscosityincrease has been achieved before the mineral oil is added. Of course,it is acceptable to add the mineral oil after the gel has completelyformed.

Mineral oil (also known as liquid petrolatum) is a by-product in thedistillation of petroleum to produce gasoline. It is a chemically inerttransparent colorless oil composed mainly of linear, branched, andcyclic alkanes (paraffins) of various molecular weights, related towhite petrolatum. Mineral oil is produced in very large quantities, andis thus relatively inexpensive. Mineral oil products are typicallyhighly refined, through distillation, hydrogenation, hydro-treating, andother refining processes, to have improved properties, and the type andamount of refining varies from product to product. Highly refinedmineral oil is commonly used as a lubricant and a laxative, and withadded fragrance is marketed as “baby oil” in the U.S. Most mineral oilproducts are very inert and non-toxic, and are commonly used as babyoils and within face, body and hand lotions in the cosmetics industry.Other names for mineral oil include, but are not necessarily limited to,paraffin oil, paraffinic oil, lubricating oil, white mineral oil, andwhite oil.

In one non-limiting embodiment the mineral oil has a high content ofisoparaffins, and is at least 99 wt % paraffinic. Because of therelatively low content of aromatic compounds, mineral oil has a betterenvironmental profile than other oils. In general, the more refined andless aromatic the mineral oil, the better. In another non-restrictiveversion, the mineral oil may have a distillation temperature above about300° C. In another non-restrictive version, the mineral oil has adynamic viscosity of greater than about 20 cps at ambient temperature,and is thus considered to be relatively high viscosity. Ambienttemperature is defined herein as about 20° C. (68° F.). In an alternate,non-limiting embodiment, the kinematic viscosity of the mineral oil at40° C. should be at least about 40 cSt. Specific examples of suitablemineral oils include, but are not necessarily limited to, PUREPERFORMANCE® 225N and 600N Base Oils available from ConocoPhillips, highviscosity ULTRA-S mineral oils from S-Oil Corporation, such as Ultra-S8, and high viscosity mineral oils from Sonneborn Refined Products, suchas GLORIA®, KAYDOL®, BRITOL® 35 USP, HYDROBRITE® 200, 380, 550, 1000,and the like. The dynamic viscosity of PURE PERFORMANCE® 225N oil at 40°C. is typically 42.7 cps, and dynamic the viscosity of 600N oil istypically 114.5 cps. The use of mineral oils herein is safe, simple andeconomical.

The amount of mineral oil needed to improve the leakoff properties of aparticular VES-gelled aqueous drill-in fluid is dependent upon a numberof interrelated factors and is difficult to predict in advance.Typically, empirical laboratory work is helpful to determine a suitableproportion. It should be an amount effective to reduce fluid loss ascompared to an otherwise identical fluid absent the mineral acid. Thedynamic viscosity and/or kinematic viscosity, molecular weightdistribution, and amount of impurities (such as aromatics, olefins, andthe like) appear to influence the effect a particular mineral oil willhave on a VES-gelled fluid at a given temperature. The effective amountof mineral oil may range from about 0.2 to about 10% by (by volume)based on the total fluid, in another non-limiting embodiment from alower limit of about 0.5% by. Independently the upper limit of the rangemay be about 3% by of the total fluid. Further details about the use ofmineral oils to reduce fluid leakoff may be found in U.S. PatentApplication Publication 2008/0103066 A1 incorporated by reference in itsentirety herein.

The viscoelastic surfactant gelled drill-in fluids herein can optionallycontain at least one viscosity enhancer. The viscosity enhancers hereinalso aid with fluid loss control. Suitable viscosity enhancers include,but are not necessarily limited to, pyroelectric particles,piezoelectric particles, and mixtures thereof. Details about the use ofpyroelectric and piezoelectric particles may be found in U.S. Pat. No.7,544,643, incorporated by reference herein in its entirety. In onenon-limiting theory or explanation, when the fluid containing theviscosity enhancers is heated and/or placed under pressure, theparticles develop surface charges that associate, link, connect, orrelate the VES micelles to one another thereby increasing the viscosityof the fluid. This is somewhat analogous to the way crosslinkers connectvarious polymer chains and is sometimes called “pseudo-crosslinking”,but the way the viscosity enhancers associate the elongated or“worm-like” VES micelles is believed to be completely different than thecrosslinking that occurs in polymers.

Suitable viscosity enhancers include, but are not necessarily limitedto, ZnO, TiO₂, berlinite (AlPO₄), lithium tantalate (LiTaO₃), galliumortho-phosphate (GaPO₄), BaTiO₃, SrTiO₃, PbZrTiO₃, KNbO₃, LiNbO₃,LiTaO₃, BiFeO₃, sodium tungstate, Ba₂NaNb₅O₅, Pb₂KNb₅O₁₅, potassiumsodium tartrate, tourmaline, topaz and mixtures thereof. The viscosityenhancer should not be soluble in the acid used in the drill-in fluid.For instance, MgO should not be used. An effective amount of theviscosity enhancer ranges from about 0.1 to about 500 pptg (about 0.012to about 60 kg/m³) based on the total aqueous viscoelastic treatingfluid. The sizes of these viscosity enhancers may range from about 1nanometer to about 2 microns nanometer-sized viscosity enhancerparticles. Alternatively, nanometer-sized particles may be used (on theorder of 10⁻⁹ to 10⁻⁸ meters). However, it was discovered that the sizeof the viscosity enhancer is not a controlling and/or primary factor ofmethods and compositions herein, that is, to control, improve or enhanceVES fluid viscosity.

In order to practice the method herein, an aqueous drill-in fluid, as anon-limiting example, is first prepared by blending acid (e.g.dicarboxylic acid blend), VES gelling agent, and internal breaker intoan aqueous fluid. The aqueous fluid could be, for example, water, brine,seawater, or mixtures thereof. Any suitable mixing apparatus may be usedfor this procedure. In one non-limiting embodiment, in the case of batchmixing, the acid, VES gelling agent, internal breaker and the aqueousfluid are blended for a short period of time sufficient to mix thecomponents together, such as for 15 minutes to 1 hour. In anothernon-limiting embodiment all of the acid, VES gelling agent and theinternal breaking composition may be added to the aqueous fluid on thefly, during a drill-in procedure.

The base fluid may also contain other conventional additives common tothe well service industry such as water wetting surfactants,non-emulsifiers, scale inhibitors, and the like, so long as they do notadversely interfere with the stated goals of the method. As notedherein, the base fluid may also contain other non-conventional additiveswhich can contribute to the breaking action of the VES fluid, and whichare added for that purpose in one non-restrictive embodiment.

Any or all of the above internal breakers, e.g. vegetable and animaloils may be provided in an extended release form such as encapsulationby polymer or otherwise, pelletization with binder compounds, absorbedor some other method of layering on a microscopic particle or poroussubstrate, and/or a combination thereof. Specifically, the plant and/orfish oils may be micro- and/or macro-encapsulated to permit slow ortimed release thereof. In non-limiting examples, the coating materialmay slowly dissolve or be removed by any conventional mechanism, or thecoating could have very small holes or perforations therein for the oilswithin to diffuse through slowly. For instance, a mixture of fishgelatin and gum acacia encapsulation coating available from ISPHallcrest, specifically CAPTIVATES® liquid encapsulation technology, canbe used to encapsulate plant, fish, synthetic and other unsaturatedbreakers. Also, polymer encapsulation coatings such as used infertilizer technology available from Scotts Company, specificallyPOLY-S® product coating technology, or polymer encapsulation coatingtechnology from Fritz Industries could possibly be adapted to themethods herein. The internal breakers could also be absorbed ontozeolites, such as Zeolite A, Zeolite 13X, Zeolite DB-2 (available fromPQ Corporation, Valley Forge, Pa.) or Zeolites Na-SKS5, Na-SKS6,Na-SKS7, Na-SKS9, Na-SKS10, and Na-SKS13, (available from HoechstAktiengesellschaft, now an affiliate of Aventis S.A.), and other poroussolid substrates such as MICROSPONGE™ (available from Advanced PolymerSystems, Redwood, Calif.) and cationic exchange materials such asbentonite clay or placed within microscopic particles such as carbonnanotubes or buckminster fullerenes. Further, the internal breakers maybe both absorbed into and onto porous or other substrates and thenencapsulated or coated, as described above.

In a typical drill-in operation, the drill-in fluid is pumped at a ratesufficient to effectively drill the reservoir. A typical drill-inoperation would be conducted by mixing a 20.0 to 60.0 gallon/1000 galwater (60.0 liters/1000 liters) amine oxide VES, such as SURFRAQ, in a2% (w/v) (166 lb/1000 gal, 19.9 kg/m³) KCl solution at a pH ranging fromabout 2 to about 6, largely set by the dicarboxylic acid blendproportion, to mention just one of the suitable acid types. The breakingcomponent may be added during the VES addition or after the VES additionusing appropriate mixing and metering equipment, or if needed in aseparate step after the treating operation is complete, or a combinationof these procedures.

In one embodiment, the methods and compositions herein are practiced inthe absence of gel-forming polymers and/or gels or aqueous fluids havingtheir viscosities enhanced by polymers. However, combination use withpolymers and polymer breakers may also be of utility. For instance,polymers may also be added to the VES drill-in fluid for fluid losscontrol purposes. Types of polymers that may serve as fluid loss controlagents include, but are not necessarily limited to, various starches,modified starches, polyvinyl acetates, polylactic acids, guar and otherpolysaccharides, hydroxyethylcellulose and other derivatized celluloses,gelatins, and the like.

The present invention will be explained in further detail in thefollowing non-limiting Examples that are only designed to additionallyillustrate the invention but not narrow the scope thereof.

General Procedure for Examples 1-4

To a blender were added tap water, HTO™ acid (high temperature organic),internal breaker (fish oil), followed by 4 vol %-viscoelastic surfactant(WG-3L—AROMOX® APA-T available from Akzo Nobel). The blender was used tomix the components on a very slow speed, to prevent foaming, for about30 minutes to form a 10% by HTO acid with 4% by VES and internal breakerfluid. At very slow speed blending, carbonate powder was slowly added toreact with the acid. The pH and viscosity of the fluid were measuredwith a pH meter and Fann-35 viscometer and recorded. After the acid isspent, the sample is loaded in a Grace 5500 rheometer to measure theviscosity vs. shear rate or time at desired temperatures. Samples wereonly observed for 5 hours or less, as indicated.

Example 1

Shown in FIG. 4 are the results of plotting viscosity as a function offluid pH for two aqueous fluids gelled with 4% of an amidoamine oxideVES containing 10% HTO acid, one with an internal mineral oil breaker 3gptg herein, and one without. Both fluids had identical curves andindicate that viscosity increases with increasing pH. This indicatesthat these fluids would start out with water-like viscosity, but whenthe acid reacts with the carbonate, is neutralized and the pH rises, theviscosity of the fluid will increase. This data also indicates thatpresence of internal breaker did not influence or prevent the VESgelling agent from yielding fluid viscosity upon acid spending. That is,presence of the internal breaker did not initially prevent or weaken theformation of viscous rod-like micelles by the VES gelling agent. This isa novel and unique phenomena, and is also synergistic. That is, what isbelieved novel and synergistic is the ability of a single, unitary fluidto initially have water-like acid viscosity but as the acid in the fluidis spent the fluid viscosity increases and thereby then acts to inhibitor prevent fluid leakoff into the reservoir due to the increasedviscosity of the gelled fluid. Once the VES viscosity is generated uponacid spending, the internal breaker is then initiated and starts toslowly and controllably work to break the VES viscosity The viscositywas measured at 100 sec⁻¹ shear rate at a room temperature of 74° F.(24° C.).

Example 2

Results showing the effect of using the mineral oil breaker on aVES-gelled acid-spent fluid at 140° F. (60° C.) are presented in FIG. 5plotting viscosity as a function of shear rate. It is readily seen thatwhen no breaker is present, the viscosity is maintained at 4000 cps atvery low shear rates, but when a breaker is present and has been fullyactivated (100% broken), the spent-acid VES-gelled fluid viscosity isclose to zero, or water-like consistency at low shear rates.

Example 3

FIG. 6 is a graph of viscosity as a function of time for a VES-gelledaqueous fluid containing spent HTO acid using fish oil as internalbreaker. The fish oil used was Bioriginal Fish Oil 18:12 TG, which isabout 18% EPA (eicosapentaenoic acid=C22:5—five double carbon bonds) and12% DHA (docosahexaenoic acid=C22:6—six double carbon bonds) highlyunsaturated fatty acids. The fluid was again measured at 160° F. (71°C.) and a shear rate of 100 s⁻¹. It is apparent that the viscosity isreduced over time for the fluids, as desired for the methods herein.

A method is provided for using aqueous acid-containing drill-in fluidsgelled with viscoelastic surfactants (VESs) having internal viscositybreakers. Compositions and methods are also furnished herein forbreaking VES-surfactant drill-in fluids controllably, completely andrelatively quickly. As may be seen, the method of gel breaking describedherein is simple, effective, safe, and highly cost-effective.

The drill-in fluids herein may be used on a one-trip basis or on acontinuous basis.

In the foregoing specification, the invention has been described withreference to specific embodiments thereof, and has been demonstrated aseffective in providing methods and compositions for using VES-gelledaqueous fluids to drill-in subterranean reservoirs where the fluids havean internal breaker mechanism. However, it will be evident that variousmodifications and changes can be made thereto without departing from thebroader spirit or scope of the invention as set forth in the appendedclaims. Accordingly, the specification is to be regarded in anillustrative rather than a restrictive sense. For example, specificcombinations of viscoelastic surfactants, internal breakers, acids,optional mineral oil, and optional viscosity enhancers and othercomponents falling within the claimed parameters, but not specificallyidentified or tried in a particular method or drill-in fluid, areanticipated to be within the scope of this invention.

The words “comprising” and “comprises” as used throughout the claims isinterpreted “including but not limited to”.

The present invention may suitably comprise, consist or consistessentially of the elements disclosed and may be practiced in theabsence of an element not disclosed.

1. A method of drilling into a subterranean formation comprising:preparing a drill-in fluid comprising water, at least one viscoelasticsurfactant (VES) and at least one acid selected from the groupconsisting of organic acids, mineral acids and combinations thereof,where the VES is present in an amount effective to increase theviscosity of the drill-in fluid but for the presence of the at least oneacid, drilling a wellbore into a subterranean formation; and at leastpartially consuming the at least one acid from the drill-in fluid byreaction of the acid with a mineral in the subterranean formation,thereby increasing the pH of the drill-in fluid to an extent sufficientto increase the viscosity of the drill-in fluid by the action of the VESin at least a portion of an annulus adjacent the wellbore to inhibitfluid loss into the formation; where the mineral comprises a carbonate,an evaporite, a salt dome, shale, and combinations thereof.
 2. Themethod of claim 1 where the drill-in fluid further comprises at leastone internal breaker.
 3. The method of claim 1 where increasing theviscosity of the drill-in fluid is accomplished by elongated micelles;the drilling fluid further comprises viscosity enhancers in aconcentration effective to associate the elongated micelles together;and the viscosity enhancers are not soluble in the acid.
 4. The methodof claim 1 where the acid is selected from the group consisting ofsuccinic acid, glutaric acid, adipic acid, acetic acid, malic acid,lactic acid, polylactic acid, glycolic acid, polyglycolic acid,methanesulfonic acid, formic acid, citric acid, tartaric acid,hydrochloric acid of a concentration of equal or less than 5%, andcombinations thereof.
 5. The method of claim 4 where the amount of acidin the drill-in fluid ranges from about 0.5 to about 30 wt %.
 6. Themethod of claim 1 where the subterranean formation comprises at least 10wt % calcium carbonate as the mineral therein.
 7. The method of claim 1where the drill-in fluid further comprises a mineral oil in an amounteffective to reduce fluid loss into the subterranean formation ascompared to an otherwise identical drill-in fluid absent the mineraloil.
 8. The method of claim 1 where the drill-in fluid further comprisesa water soluble salt selected from the group consisting of NaCl, KCl,NH₄Cl, CaCl₂, MgCl₂, NaBr, CaBr₂, sodium formate, potassium formate,sodium salicylate, and combinations thereof,
 9. A method of drillinginto a subterranean formation comprising: preparing a drill-in fluidcomprising water, at least one viscoelastic surfactant (VES) and fromabout 0.5 to about 30 wt %, based on the total drill-in fluid, of atleast one acid selected from the group consisting of organic acids,mineral acids and combinations thereof, where the VES is present in anamount effective to increase the viscosity of the drill-in fluid but forthe presence of the at least one acid, and the acid is selected from thegroup consisting of succinic acid, glutaric acid, adipic acid, aceticacid, malic acid, lactic acid, polylactic acid, glycolic acid,polyglycolic acid, methanesulfonic acid, formic acid, citric acid,tartaric acid, hydrochloric acid of a concentration of equal or lessthan 5%, and combinations thereof, drilling a wellbore into asubterranean formation; and at least partially consuming the at leastone acid from the drill-in fluid by reaction of the acid with a mineralin the subterranean formation, thereby increasing the pH of the drill-influid to an extent sufficient to increase the viscosity of the drill-influid by the action of the VES in at least a portion of an annulusadjacent the wellbore to inhibit fluid loss into the formation; wherethe mineral comprises a carbonate, an evaporite, a salt dome, shale, andcombinations thereof.
 10. The method of claim 9 where the drill-in fluidfurther comprises at least one internal breaker.
 11. The method of claim9 where increasing the viscosity of the drill-in fluid is accomplishedby elongated micelles; the drill-in fluid further comprises viscosityenhancers in a concentration effective to associate the elongatedmicelles together; and the viscosity enhancers are not soluble in theacid.
 12. The method of claim 9 where the subterranean formationcomprises at least 10 wt % calcium carbonate as the mineral therein. 13.The method of claim 9 where the drill-in fluid further comprises amineral oil in an amount effective to reduce fluid loss into thesubterranean formation as compared to an otherwise identical drill-influid absent the mineral oil.
 14. A method of drilling into asubterranean formation comprising: preparing a drill-in fluid comprisingwater, at least one viscoelastic surfactant (VES), at least one internalbreaker and at least one acid selected from the group consisting oforganic acids, mineral acids and combinations thereof, where the VES ispresent in an amount effective to increase the viscosity of the drill-influid but for the presence of the at least one acid; drilling a wellboreinto a subterranean formation; at least partially consuming the at leastone acid from the drill-in fluid by reaction of the acid with a mineralin the subterranean formation, thereby increasing the pH of the drill-influid to an extent sufficient to increase the viscosity of the drill-influid by the action of the VES in at least a portion of an annulusadjacent the wellbore to inhibit fluid loss into the formation; andsubsequently activating the internal breaker thereby reducing theviscosity of the drill-in fluid adjacent the wellbore; where the mineralcomprises a carbonate, an evaporite, a salt dome, shale, andcombinations thereof.
 15. The method of claim 14 where increasing theviscosity the drill-in fluid is accomplished by elongated micelles; thedrill-in fluid further comprises viscosity enhancers in a concentrationeffective to associate the elongated micelles together; and where theviscosity enhancers are not soluble in the acid.
 16. The method of claim14 where the acid is selected from the group consisting of succinicacid, glutaric acid, adipic acid, acetic acid, malic acid, lactic acid,polylactic acid, glycolic acid, polyglycolic acid, methanesulfonic acid,formic acid, citric acid, tartaric acid, hydrochloric acid of aconcentration of equal or less than 5%, and combinations thereof. 17.The method of claim 16 where the amount of acid in the drill-in fluidranges from 0.5 to about 30 wt %.
 18. The method of claim 14 where thesubterranean formation comprises at least 10 wt % calcium carbonate asthe mineral therein.
 19. The method of claim 14 where the drill-in fluidfurther comprises a mineral oil in an amount effective to reduce fluidloss into the subterranean formation as compared to an otherwiseidentical drill-in fluid absent the mineral oil.
 20. The method of claim14 where activating the internal breaker comprises heating the drill-influid to a temperature effective to activate the breaker.